The present invention relates to aqueous-based emulsified consolidating agents suitable for use during drill-in operations. When drilling into a subterranean formation to reach a producing zone, it is generally necessary to drill through a substantial distance of non-producing formation before reaching the desired zone or zones. When the wellbore is drilled through the non-producing sections, a drilling mud is pumped into the drill string within the well and is then drawn up to the surface of the well through the annulus surrounding the drill string. The drill cuttings are entrained in the drilling mud and withdrawn from the well with the fluid. In addition to removing cuttings, the drilling mud also serves other functions such as lubricating the drill string and bit, cooling the drill bit, and providing sufficient hydrostatic pressure down hole to prevent the flow of formation fluids into the well. Generally, the drilling mud is a liquid with solids suspended therein. The solids function to impart desired rheological properties to the drilling mud and also to increase its density in order to provide a suitable hydrostatic pressure at the bottom of the well. The drilling mud may be either an aqueous-base mud or an oil-base mud.
While drilling muds are highly effective and cost relatively little, they are not suitable for drilling into the producing zone of a subterranean formation. This is because the make-up of the drilling mud tends to damage the producing formation and tends to complicate the completion process. Drilling muds minimize fluid loss by using solid fluid loss control agents which tend to form filtercakes and to shut off the invasion of fluid into formation. For these reasons, specially formulated “drill-in” compositions are used to drill the wellbore into producing portions of a subterranean formation so as to minimize damage and maximize production of exposed zones and to facilitate any necessary well completion needed. Unlike a drilling fluid, a drill-in fluid generally contains few solids, and what solids it does contain are often size controlled to minimize penetration or invasion into the formation matrix to avoid damaging the production formation. Generally, only those additives needed for filtration control and cuttings carrying are present in a drill-in fluid. These solids are designed to be removed physically or chemically after one or more completion operations before the well is put on production.
After a well is drilled into a portion of a subterranean formation, a variety of stimulation and completion operations may be performed before placing the well into production. One common operation involves consolidating the formation particulates to minimize the production of solids along with the desired fluids. In addition to maintaining a relatively solids-free production stream, consolidating particulates also aid in protecting the production flow paths of the formation. Flow of unconsolidated particulate material, such as formation fines, through the conductive channels in a subterranean formation tends to clog the conductive channels and may damage the interior of the formation or equipment.
There are several known techniques used to control particulate migration, some of which may involve the use of consolidating agents. The term “consolidating agent” as used herein includes any compound that is capable of minimizing particulate migration in a subterranean formation and/or modifying the stress-activated reactivity of subterranean fracture faces and other surfaces in subterranean formations. Such consolidating agents may be used once the drill-in process is complete by placing the consolidating agent into the formation such that it coats the unconsolidated particulates, making them adhere to one another and to consolidated matter within the formation such that the coated particulates are less likely to migrate through the conductive channels in the subterranean formation.
In producing zones that are weakly consolidated, it is desirable to stabilize the formation surrounding the wellbore as soon as possible to avoid excess clean-up costs and to ensure the integrity of the wellbore itself. Thus, it would be desirable to have a consolidating agent that could provide a means for consolidating the formations surrounding the wellbore during the drilling phase of the well, instead of performing separate sand control completion, such as gravel packing, frac-packing, or sand consolidation, at a later time. However, any fluid invasion or penetration into the formation of the production interval is considered to be negative for the potential production of the well and so drill-in fluids must be carefully designed.